Fourth Quarter and Year End 2015 Earnings Review. Todd Stevens President & CEO Los Angeles, CA February 29, 2016 Mark Smith Sr.

Transcription

1 Fourth Quarter and Year End 2015 Earnings Review Todd Stevens President & CEO Los Angeles, CA February 29, 2016 Mark Smith Sr. EVP & CFO

2 Forward-Looking / Cautionary Statements This presentation contains forward-looking statements that involve risks and uncertainties that could materially affect our expected results of operations, liquidity, cash flows and business prospects. Such statements specifically include our expectations as to our future financial position, drilling program, production, projected costs, future operations, hedging activities, future transactions, planned capital investments and other guidance. Actual results may differ from anticipated results, sometimes materially, and reported results should not be considered an indication of future performance. For any such forwardlooking statement that includes a statement of the assumptions or bases underlying such forward-looking statement, we caution that, while we believe such assumptions or bases to be reasonable and make them in good faith, assumed facts or bases almost always vary from actual results, sometimes materially. Factors (but not necessarily all the factors) that could cause results to differ include: commodity price fluctuations; the effect of our debt on our financial flexibility; sufficiency of our operating cash flow to fund planned capital expenditures; the ability to obtain government permits and approvals; effectiveness our capital investments; our ability to monetize selected assets; restrictions and changes in restrictions imposed by regulations, including those related to our ability to obtain, use, manage or dispose of water or use advanced well stimulation techniques like hydraulic fracturing; risks of drilling; tax law changes; competition with larger, better funded competitors for and costs of oilfield equipment, services, qualified personnel and acquisitions; the subjective nature of estimates of proved reserves and related future net cash flows; restriction of operations to, and concentration of exposure to events such as industrial accidents, natural disasters and labor difficulties in, California; limitations on our ability to enter efficient hedging transactions; the recoverability of resources; concerns about climate change and air quality issues; lower-than-expected production from development projects or acquisitions; catastrophic events for which we may be uninsured or underinsured; the effects of litigation; cyber attacks; operational issues that restrict market access; and uncertainties related to the spin-off and the agreements related thereto. Material risks are further discussed in Risk Factors in our Annual Report on Form 10-K and subsequent 10Qs available on our website at crc.com. Words such as "aim," "anticipate," "believe," "budget," "continue," "could," "effort," "estimate," "expect," "forecast," "goal," "guidance," "intend," "likely," "may," "might," "objective," "outlook," "plan," "potential," "predict," "project," "seek," "should," "target, "will" or "would" or similar expressions that convey the prospective nature of events or outcomes generally indicate forward-looking statements. Any forward-looking statement speaks only as of the date on which such statement is made and CRC undertakes no obligation to correct or update any forward-looking statement, whether as a result of new information, future events or otherwise, except as required by applicable law. Some of the data in this presentation is from external sources as noted. While we believe it is accurate, we have not independently verified the data and do not represent or warrant that it is accurate, complete or reliable. This presentation includes financial measures that are not in accordance with United States generally accepted accounting principles ( GAAP ), including PV-10 and adjusted EBITDAX. While management believes that such measures are useful for investors, they should not be used as a replacement for financial measures that are in accordance with GAAP. For a reconciliation of adjusted EBITDAX to the nearest comparable measure in accordance with GAAP, please see the Appendix. 2

3 Diverse Resource Base Interests in 4 of the 12 largest fields in the lower 48 states 644 MMBoe proved reserves (12/31/2015) Largest producer in California on a gross operated basis with significant exploration and development potential Shareholder Value Focus Internally funded capital investment program Optimized capital allocation Portfolio of Lower-Risk, Lower- Decline Opportunities Oil weighted reserves Broad exploration and development program California Heritage Strong track record of operations since 1950s Longstanding community and state relationships Actively involved in communities with CRC operations Management Expertise Operations exclusively in California Assembled largest privately-held land position in California Operator of choice in sensitive environments 3

4 Management Priorities and Response Priorities 1. Address Balance Sheet 2. Adjust Activity Levels for Current Environment Live within means and align capital investments with projected cash flow 3. Focus on base production and protect our margins 4. Right-size costs for the current operating environment Execution Balanced 2015 operating cash flows of $403 million with capital investment of $401 million Exceeded 2015 production target with 90% of target capital investment Delivered average 4Q15 oil production of 102,000 bbls/day, which was 3% higher than the FY 2014 average of 99,000 bbls/day and down just 1% from 3Q15 Focused on costs. Total cash costs per boe, excluding interest expense, declined ~18% in 4Q15 vs 4Q14 Op Cash costs down to $15.51/Boe for 4Q15, compared to $16.65/Boe in 4Q14 Expected run-rate G&A to be roughly $4.00/Boe for 2016 Executed debt exchange that reduced principal by $563 million 4

5 $ MM FY ($MM ) Living Within Cash Flow Q15 2Q15* 3Q15 4Q15* FY 2015 Adj. EBITDAX** Operating Cash Flow Capital Investment -75 * Operating cash flow includes a semi-annual cash property tax payment ** See Appendix for reconciliations to GAAP 5

6 Capital Allocation Approach Portfolio Management since spin-off Three principal drivers: o Maximize long-term value VCI > 1.3 o Oil production growth o Financial discipline self-funding business Results in combination of projects that provide quick payback (workovers) and longer term value / future growth (steamfloods/waterfloods). Value Creation Index VCI = PV10 pre-tax cash flows PV10 of investments Measures value created per dollar investment ( Bang for the buck ) 6

7 Mboe/d $MM Strong Execution Track Record Total Production Guidance vs. Actual Capital Investment Guidance vs. Actual Q15 2Q15 3Q15 4Q15 0 1Q15 2Q15 3Q15 4Q15 Production Guidance Range Actual Capital Investment Guidance Range Capex Actual Delivered production toward the high end of guidance with a lower than target capital investment 7

8 Best in Class Corporate Decline Rate Unlabeled operators include : AMXG, AREX, BBG, BCEI, CLR, CPE, CRK, CWEI, CXO, EGN, EOG, EPE, EXXI, FANG, GDP, HK, JONE, LPI, MPO, NFX, OAS, PDCE, PE, PVA, PXD, ROSE, RSPP, SFY, SM, SN, TPLM, WTI, XEC Source: ITG IR, raw data provided by Drilling Info, Inc. 8

9 Mboe/d Net Development Capital ($MM) Resilient Asset Base 90.0 Elk Hills Field 1, , Net Production MBOED Net Development Capital ($MM) 9

10 Defending Margins Through Efficiencies and Focus on Cash Costs Cash Costs $/Boe $35 $30 $25 $20 $15 $10 $5 $ Average = $29.57 $2.23 $1.06 $1.69 $ Average = $24.91 $1.11 $0.52 $0.34 $0.49 $19.00 $19.03 $18.35 $16.65 $16.20 $16.59 $16.91 $15.51 $3.74 $3.88 $3.79 $3.55 $3.65 $3.63 $2.89 $2.10 $4.97 $5.00 $5.28 $5.57 $5.09 $5.13 $4.61 $4.80 1Q14 2Q14 3Q14 4Q14 1Q15 2Q15 3Q15 4Q15 1Q16E Adj G&A* Taxes (non income) Production Costs Exploration Guidance 4Q15 production costs per boe were approximately 7% lower year over year. Lower fourth quarter costs reflected cost reductions across the board, particularly in well servicing efficiency, surface operations and energy use, and were also aided by lower natural gas and power prices. * Adjusted G&A expenses exclude early retirement and severance costs which amounted to $10 million in 2Q15, $62 million in 3Q15 and $(5) million in 4Q15. 10

11 Jan-16 Jul-16 Jan-17 Jul-17 Jan-18 Jul-18 Jan-19 Jul-19 Jan-20 Jul-20 Jan-21 Jul-21 Jan-22 Jul-22 Jan-23 Jul-23 Jan-24 Jul-24 Focus on Balance Sheet Capitalization as of 12/31/15 ($MM) 1st Lien Secured RCF st Lien Secured Term Loan 1,000 Senior 2nd Lien Notes 2,250 Senior Unsecured Notes 2,154 Total Debt 6,143 Less cash (12) Total Net Debt 6,131 Equity (916) Total Net Capitalization 5,215 Total Net Debt / Net Capitalization 118% Total Net Debt / LTM Adjusted EBITDAX 6.8x LTM Adjusted EBITDAX / Interest Expense 2.8x PV-10 2 / Total Net Debt 0.8x Total Net Debt / Proved Reserves ($/Boe) $9.52 Total Net Debt / PD Reserves ($/Boe) $12.75 Total Net Debt / Production ($/Boepd) $38,319 1 On February 23, 2016 we amended the Credit Facilities and reduced our borrowing base to $2.3 billion. After taking into account borrowing base limitations, we now have the ability to incur total borrowings under the RCF of $1.3 billion less outstanding amounts (currently ~$600MM)*, subject to compliance with our quarterly financial covenants which currently further limit our availability. 2 PV-10 as of 12/31/15 based on SEC five-year rule applied to PUDs using SEC price deck. See Appendix for reconciliation to GAAP. Deleveraging is a priority Ratings action initiated transition to secured borrowing base facility Borrowing base of $2.3 billion effective February 2016 Approximately $1.6 billion outstanding under senior credit facilities currently* Debt Maturities ($MM)** $2,500 $2,000 $1,500 $1,000 $500 $0 $25 * As of 2/29/16 ** As of 12/31/15 Term Loan $625 $433 $829 $2,

12 Total Debt ($M) Brent Oil ($/Bbl) Deleveraging Update Total Debt $7,000 $6,000 $ $5,000 $4,000 $3,000 $2,000 $55 $64 $48 $37 $ $1, $0 10/1/14 3/31/15 6/30/15 9/30/15 12/31/15 2/29/16 Long Term Notes Term Loan Revolving Credit Facility Oil Price 0 Given the significant decline in oil prices, focused on 1) free cash flow to reduce residual working capital from Spin, and 2) successful execution of debt exchange 12

13 Deleveraging Options We have assessed various deleveraging alternatives and are taking decisive steps to delever the balance sheet UPSTREAM JV M&A MIDSTREAM MLP Drop into Existing MLP Sale Triple Net Lease CAPITAL MARKETS Debt Exchange AVAILABLE ASSETS 2.4 Million Acres ~60% of Land held in Fee Large Economic Development Project Inventory Seismic Robust Exploration Portfolio AVAILABLE ASSETS 14 Gas Plants with 650 MMcfd Capacity Elk Hills has largest Gas Plant Complex in CA 300 Compressors / Stations with 395,000 HP of Compression 600 MW Electrical Generation with 700 miles of High Voltage Transmission Lines 305 Tank Settings / LACT / Sales Facilities 74 Water Plants / Treatment Facilities 50 Steam Generators with 220,000 Bbl Steam Capacity ~20,000 Miles of Pipelines TRANSACTION Exchange offer for Unsecured Notes reduced debt by $563 million 13

14 Amendment Summary of General Terms & Conditions Revised Amendment Previous Maximum Leverage First Lien Leverage Ratio suspended through 12/31/16; At and after 3/31/17 : < 2.25x Maximum First Lien Secured Leverage Ratio: 2.25x Minimum Interest Coverage 03/31/16 : > 2.00x 06/30/16 : > 1.50x 09/30/16 : > 1.25x 12/31/16 : > 0.70x Thereafter: > 2.00x 2.00x Cumulative Minimum EBITDAX 03/31/16 : $55mm 06/30/16 : $130mm 09/30/16 : $190mm 12/31/16 : $250mm N/A Borrowing Base, Revolver Commitment, Total Commitment $2.3 Bn Borrowing Base $1.6 Bn Revolver Commitment $2.6 Bn Total Commitment $3.0 Bn Borrowing Base $2.0 Bn Revolver Commitment $3.0 Bn Total Commitment Redetermination Semi-Annually, May 1st and November 1st Annually May 1st Anti-hoarding Provisions Cash > $150mm must be used to the repay the revolver Cash > $250mm must be used to the repay the revolver Other Maximum Capital Expenditures: $100mm General lien basket of up to $50mm Accordion and Swingline eliminated Increase of 75 bps across pricing grid General lien basket of greater of $200mm and 1.5% of Consolidated Total Assets 14

15 Amendment Summary of Liability Management Terms Revised Amendment Previous Sale of Borrowing Base Properties Sale of Non-Borrowing Base Properties 100% of proceeds used to repay first the term loan, then the revolver 100% of proceeds used to repay first the term loan, then the revolver except: 40% of proceeds can be used to repurchase: 2L notes at a minimum of 40% discount Unsecured notes at a minimum of 60% discount Subject to potential repayment of revolver due to resultant borrowing base reduction $150 million + 50% of proceeds could be used to repurchase senior notes and other junior debt Deleveraging Debt Basket A May incur debt of $1Bn secured with junior liens 40% of proceeds can be used to repurchase: 2L notes at a minimum of 40% discount Unsecured notes at a minimum of 60% discount Deleveraging Debt Basket B May incur debt of up to $200mm secured with liens on nonborrowing base properties in order to repurchase: 2L notes at a minimum of 40% discount Unsecured notes at a minimum of 60% discount N/A N/A Junior Notes Basket Used in the December 2015 bond exchange Up to $2.25 Bn in junior notes 15

16 Drilling and Workover Inventory ($MM) Progressing Inventory to VCI Threshold 2500 Economic Project Inventory $40 $50 Brent Marker Price ($/Bbl) VCI 1.3 VCI

17 Diverse Assets with Flexible Development Opportunities 2015 Net Proved Reserves (MMBoe) % Oil Net Proved 1 72% Pre-Tax Proved PV-10 ($ billion) Avg. Net Production (MBoe/d) % Oil Production 65% 2015 Net Acreage (million acres) Identified Gross Locations 1 23,450 Diversity of basins, drive mechanisms Predictable production, low decline rates Multiple stacked reservoirs Development targets include repeatable projects with low technical risk San Joaquin Basin Los Angeles Basin Ventura Basin Sacramento Basin 2015 Net Proved Reserves (MMBoe) % Proved Developed 72% 80% 77% 100% 2015 % Liquids Net Proved 1 78% 98% 89% 0% 2015 Avg. Net Production (MBoe/d) % Oil Production 58% 100% 67% 0% 2015 Net Acreage (million acres) < Identified Gross Drilling Locations 1 19,150 1,650 1,500 1,150 1 As of 12/31/15. Drilling locations exclude 6,400 gross prospective locations. 2 See Appendix for reconciliation to GAAP. Figures shown are full year 2015, unless otherwise noted. 17

18 Self-Funded Capital Investment Program Commentary 2015 actual capital investment of $401 million was directed almost entirely toward oil-weighted investments Total and oil production increased 1% and 5% respectively in 2015 without exceeding cash flows Expect multi-year crude oil maintenance capital range of $600-$700 million per year to maintain flat crude oil production * Primary tenet for 2016 capital program of $50mm is to invest within cash flow, emphasizing mechanical integrity and safe operations 2015 Drilling Capital Actuals By Basin 2015 Total Capital Actuals Exploration $15 4% Other 1 $81 20% Dev. Facilities $120 30% 2015 Drilling Capital Actuals By Drive Total: $401 million Drilling $130 32% Workovers $55 14% Los Angeles $45 35% Total: $130 million Waterfloods $50 38% Primary $10 8% San Joaquin $85 65% 1 Other includes maintenance and occupational health, safety and environmental projects, seismic and other investments. * Calculated over 3 years based on current operating costs and expenses in the current commodity environment. Steamfloods $70 54% 18

19 Capex Reduction 2015 Actual FY 2016E Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec 1Q 2Q 3Q 4Q RIGS Quarterly Operations CAPEX, $mm $133 $95 $95 $78 $50* 2016 Capital Investment Plan to focus on mechanical integrity and safe operations Monitor cash flow throughout the year and retain flexibility to increase investments in drilling and capital workovers to the extent crude oil prices show sustained improvement, while abiding by financial covenants * Full Year 2016 Guidance 19

20 Opportunistically Built Hedge Portfolio* Q Q Q Q Calls Barrels per Day 35,500 35,500 3,000 3,000 30,000 23,300 Wtd Avg Ceiling Price per Barrel $66.15 $66.15 $74.42 $74.42 $55.68 $57.99 Puts Barrels per Day 33,800 55,500 28,000 3, Wtd Avg Floor Price per Barrel $51.75 $50.14 $50.65 $ Swap Barrels per Day - - 1,000 1, Wtd Avg Price per Barrel - - $61.25 $ * As of February 23, 2016 Hedge book started at zero post spin; we target hedges on 50% of production Strategy focuses on protecting cash flow for capital investments and covenant compliance Q averages include Brent-based puts for 10,000 barrels of oil per day of our March 2016 production at $46 per barrel 20

21 % of WTI $/Bbl $/Mcf CRC Price Realizations Oil Price Realization* Gas Price Realization* $120 $110 $100 $90 $80 $70 $60 $50 $40 $30 WTI Realizations Brent $ $ $ $99.51 $ $ $93.00 $95.12 $94.21 $97.97 $ $92.30 $53.64 $49.19 $ NYMEX Realizations $4.31 $3.73 $4.39 $4.11 $2.94 $4.34 $3.66 $2.75 $2.81 $ Realization % of WTI 109% 110% 106 % 99% 97% Realization % of NYMEX 105% 105 % 102 % 101% 97% NGL Price Realization - % of WTI 80% 74% 70% 56% 60% 51% 51% 50% 40% 40% 30% 20% 10% 0% Oil pricing continued to deteriorate over 2015 NGL pricing has followed the general energy market lower. Downside pressure has come from extraction volumes as gas production throughout the U.S. has continued to increase Natural gas prices declined in 2015 due to continued supply growth, lower demand due to mild weather, record storage inventory levels and lower industrial demand * Reflects realizations with hedges 21

22 $ MM Operating Cash Flow CRC Executing on Controllable Items , FY 2014 Volume Price Costs Interest Working Capital and Other 403 FY

23 Cost Variance 4Q14 3Q15 4Q15 Production costs ($/Boe) Taxes other than on income ($MM) Exploration expense ($MM) Interest expense ($MM) $16.65 $16.91 $15.51 $54 $42 $30 $68 $5 $7 NA $82 $82 23

24 Boe/D Capital Investment ($MM) Modest Production Decline Despite Drastically Lower Capital Investment 170, , ,000 Quarterly capital Investment of $520mm -3,000-6,000-1,000 $500 $ ,000 $ , , ,000 $ , ,000 Quarterly Capital Investment of $78mm $ ,000 4Q14 Oil Gas NGL 4Q15 $0 24

25 Mboe/d Focus on Oil Enhances Base & Margins Production By Stream (MBoe/d) Average Total 159 Mboe/d Production 160 Mboe/d Average Oil 99 MBbl/d Production 104 MBbl/d 1Q14 2Q14 3Q14 4Q14 1Q15 2Q15 3Q15 4Q15 1Q16E FY 2014 FY 2015 FY 2016E Oil NGL Gas Guidance 25

26 4Q15 Results Summary Comparison 4Q14 3Q15 4Q15 Adjusted EPS* ($0.02) ($0.22) ($0.20) Oil Production 105 MBbl/d 103 MBbl/d 102 MBbl/d Total Production 165 MBoe/d 158 MBoe/d 155 MBoe/d Realized Oil Price w/hedge ($/Bbl) $68.54 $47.79 $45.88 Realized NGL Price ($/Bbl) $34.41 $16.92 $19.56 Realized Natural Gas Price w/ hedge($/mcf) $4.00 $2.83 $2.44 Adjusted EBITDAX* $454 mm $212 mm $226 mm Capital Investments $520 mm $95 mm $78 mm Cash Flow from Operations $504 mm $180 mm ($9 mm)** *See Appendix for reconciliations to GAAP **Operating cash flow Includes a semi-annual cash property tax payment 26

27 1Q16 Guidance Anticipated Realizations Against the Prevailing Index Prices for 1Q16 Oil 83% to 87% of Brent NGLs 45% to 49% of Brent Natural Gas 96% to 100% of NYMEX Production, Capital and Income Statement Guidance Production 145 to 150 MBOE per day Capital $18 to $28 million Production Costs $14.50 to $15.00 per BOE G&A $3.95 to $4.15 per BOE DD&A $10.30 to $10.50 per BOE Taxes other than on income $36 to $40 million Exploration expense $7 to $11 million Interest expense $74 to $78 million Cash Interest $47 to $51 million Income tax expense rate 10% Cash tax rate 0% See Attachment 9 of the 4Q15 earnings press release issued February 29, 2016 for more details. 27

28 Poised to Take Advantage of a Commodity Price Recovery World-Class Resource Base: Large inventory of assets across basins and drive mechanisms that provide strong returns through the commodity price cycle Exceptional Operating Leverage: High level of operating leverage and control favorably positions CRC to capitalize on a strengthening commodity market Stable Base: Diverse and stable assets enable a predictable production profile with low base declines Sacramento Basin 14 MMBoe Proved Reserves 7 MBoe/d production San Joaquin Basin 451 MMBoe Proved Reserves 110 MBoe/d production Ventura Basin 47 MMBoe Proved Reserves 9 MBoe/d production Focused and Experienced Management Team: Proactive executive team that swiftly executes strategic objectives NY00813G / _1.WOR Los Angeles Basin 132 MMBoe Proved Reserves 34 MBoe/d production Reserves as of 12/31/15; Production figures reflect average FY 2015 rates. 28

29 California Resources Corporation Appendix 29

30 Non-GAAP Reconciliation for Adjusted EBITDAX For the Fourth Quarter Ended December 31, For the Twelve Months Ended December 31, ($ in millions) Net Income/(loss) ($3,282) ($2,091) ($3,554) ($1,434) Interest expense Income taxes expense/(benefit) (1,757) (1,431) (1,922) (987) Depreciation, depletion and amortization ,004 1,198 Exploration expense Asset Impairments 4,852 3,402 4,852 3,402 Other (a) Adjusted EBITDAX $226 $454 $906 $2,548 Net cash provided by operating activities ($9) $504 $403 $2,371 Interest expense Cash income taxes - (17) Cash exploration expenses Changes in operating assets and liabilities 104 (155) 147 (143) Other, net Adjusted EBITDAX $226 $454 $906 $2,548 (a) Includes non-cash and unusual or infrequent charges. 30

31 Non-GAAP Reconciliation for PV-10 ($ in millions) At December 31, 2015 PV-10 of Proved Reserves $5,059 Present value of future income taxes discounted at 10% (1,035) Standardized Measure of Discounted Future Net Cash Flows $4,024 PV-10 is a non-gaap financial measure and represents the year-end present value of estimated future cash inflows from proved oil an natural gas reserves, less future development and production costs, discounted at 10% per annum to reflect the timing of future cash flows and using SEC prescribed pricing assumptions for the period. PV-10 differs from Standardized Measure because Standardized Measure includes the effects of future income taxes on future net cash flows. Neither PV-10 nor Standardized Measure should be construed as the fair value of our oil and natural gas reserves. PV-10 and Standardized Measure are used by the industry and by our management as an asset value measure to compare against our past reserves bases and the reserves bases of other business entities because the pricing, cost environment and discount assumptions are prescribed by the SEC and are comparable. PV-10 further facilitates the comparisons to other companies as it is not dependent on the tax paying status of the entity. 31

32 Non-GAAP Reconciliation for Adjusted EPS For the Fourth Quarter Ended December 31, For the Third Quarter Ended September 30, For the Twelve Months Ended December 31, ($ in millions) Adjusted net Income/(loss) $(77) $(7) $(104) $(311) $650 Asset impairments (4,852) (3,402) - (4,852) (3,402) Write-down of certain other assets (71) - - (71) - Non-cash hedge related gains 19 - (53) 52 - Early retirement and severance costs 5-62 (67) - Rig terminations and other costs (5) (52) 3 (11) (52) Debt transaction costs (8) - - (8) - Spin-off and transition related costs - (55) - - (55) Valuation allowance for deferred tax assets (294) - - (294) - Tax effects of these items and related adjustments 2,001 1, ,008 1,425 Net income / (loss) $(3,282) $(2,091) $(86) $(3,554) $(1,434) EPS diluted $(8.54) $5.47 $(0.27) $(9.27) $(3.75) Adjusted EPS diluted $(0.20) $0.02 $(0.22) $(0.81) $1.67 Weighted average diluted shares outstanding (a) (a) On November 30, 2014, the Spin-off date from Occidental Petroleum Corporation, we issued million shares of our common stock. Additional shares were distributed to our employees and vested in December. For comparative purposes, and to provide a more meaningful calculation of weighted-average shares outstanding, we have assumed these amounts to be outstanding for each period prior to the Spin-off. 32